M. W. Da Silva, Petrobras, São José dos Campos, Brazil
Part 1 of this article—published in the November issue of Hydrocarbon Processing—described the relevance of the propylene market and how it can be a significant opportunity for integrated players in the downstream processing industry.
Part 1 made reference to a “blue ocean strategy” to classify the competitive markets in the hydrocarbon processing industry (HPI).1 In this article, the author defines the conventional market as a “red ocean” where the players tend to compete in the existing market by focusing on defeating competitors through the exploration of existing demand, leading to low differentiation and low profitability. The “blue ocean” is characterized by a non-explored (or little-explored) space, creating and developing new demand and reaching differentiation. This model can be applied (with some specificities once in a commodity market) to the HPI, considering the traditional transportation fuel refineries and the petrochemicals sector.
This work will detail the available processing routes capable of maximizing propylene yield in refineries, allowing refiners to gain advantage from the propylene market.
Propylene production routes. Today, a major part of the propylene market is supplied by steam cracking units, but a sizable portion of global propylene demand is from the separation of liquefied petroleum gas (LPG) produced in fluid catalytic cracking units (FCCUs). FIG. 9 shows a feedstocks and derivatives profile in a typical FCCU.
Normally, LPG produced in FCCUs comprises around 30% of propylene production, and the added value of the propylene is nearly 2.5 times that of LPG. The installation of propylene separation units presents an attractive return on investment. Despite the advantage, a side effect of separating propylene from LPG is that the fuel is heavier, leading to challenges, mainly in colder regions. In these cases, alternative routes are to segregate butane and send that stream to the gasoline pool, add propane to the LPG, or add LPG from natural gas. It is important to consider that some of these alternatives reduce the LPG offer, which can be a severe restriction on market demand.
A significant challenge in the propylene production process is the separation of propane and propylene. The separation is generally challenged by distillation since the relative volatility between propylene and propane is close to 1.1. This challenge results in many equilibrium stages and high internal reflux flowrates.
Two technologies are normally employed in propylene-propane separation towers: heat-pump and high-pressure configurations.
The high-pressure technology applies a traditional separation process that uses a condenser with cooling water to promote the condensation of top products. In this case, it is necessary to apply sufficient pressure to promote the condensation of products in ambient temperature. Furthermore, the reboiler uses steam or another available hot source. The adoption of the high-pressure separation route requires the availability of low-pressure steam in refining hardware. In some cases, this can be a restrictive characteristic, and the heat pump configuration is more attractive despite the higher capital requirements.
The separation process applying heat pump technology uses the heat supplied by the condensation of top products in the reboiler. In this case, the reboiler and the condenser are the same equipment. To compensate for the non-idealities, it is necessary to install an auxiliary condenser with cooling water.
The application of heat pump technology allows the operating pressure to decrease from 20 bar to 10 bar. This increases the relative volatility of the propylene-propane separation process, making the separation process easier and, consequently, reducing the number of equilibrium stages and internal reflux flowrates required for the separation.
Normally, when the separation process by distillation is challenging (with relative volatilities lower than 1.5), the use of this heat pump technology is more attractive. Furthermore, some variables must be considered during the selection of the best technology for the propylene-propane separation process, such as the availability of utilities, the temperature gap in the column and installation costs.
Normally, propylene is produced in refineries to specific specifications. The polymer grade that is most common and that has a higher added value of purity (a minimum of 99.5%) is directed to the polypropylene (PP) market. The chemical grade with purities between 90% and95% is normally directed to other uses.
LPG from FCCUs is pumped to a depropanizer column, where the light fraction (essentially a mixture of propane and propylene) is recovered in the top of the column and sent to a deethanizer column. Depending on the refinery’s configuration, the bottoms (butanes) are pumped to the LPG or gasoline pools. The top stream of the deethanizer column (lighter fraction) is sent back to the FCCU, where it is incorporated into the refinery’s fuel gas pool. In some cases, it can be directed to a petrochemical plant to recover light olefins (mainly ethylene) present in the stream, while the bottom of the deethanizer column is pumped to the C3 splitter column, where the separation of propane and propylene is carried out. The propane recovered in the bottom of the C3 splitter is sent to the LPG pool, where the propylene is sent to a propylene storage park. The feed stream passes through a caustic wash treating process to remove some contaminants that can lead to deleterious effects in petrochemical processes (e.g., carbonyl sulfide, which can be produced in the FCCU through the reaction between carbon monoxide and sulfur in the riser).
The maximum olefins operation mode in FCCUs. According to market demand, FCCUs can be optimized to produce the highest demanded derivatives. Refiners facing gasoline surplus markets can operate FCCUs in a maximum olefins operation mode to minimize the production of cracked naphtha. In this operational mode, the FCCU operates under high severity—i.e., high operational temperatures and a high catalyst-to-oil ratio.
The cracked naphtha may show an improvement in octane number despite a lower yield due to a higher concentration of aromatics. In some cases, the refiner can use cracked naphtha to improve LPG yield.
In maximum LPG operation mode, the primary restrictions are the cold area processing capacity, metallurgic limits in the hot section of the unit, treating section processing capacity and the top systems of the main fractionating column. In markets with a decreasing demand for transportation fuels, this is the most common FCCU operations mode.
Through changing the reaction severity, it is possible to maximize the production of petrochemical intermediates, primarily propylene, in conventional FCCUs (FIG. 10). The use of FCC catalyst additives (e.g., ZSM-5) can increase propylene production by up to 9%. Despite the higher operating costs, the increased revenues from the higher added value of derivatives should lead to a positive financial result for the refiner. A relatively common strategy also applied to improving LPG and propylene yields in the FCCU is the recycling of cracked naphtha, which leads to an over-cracking of the gasoline range molecules.
Today, the declining demand for transportation fuels has forced some refiners to optimize their FCCUs to maximize propylene yield. Among the alternatives for maximizing propylene yield in the FCCU are the use of ZSM-5 as an additive to FCC catalysts, along with adjusting process variables to the most severe conditions, including higher temperatures and catalyst circulation rates. Another alternative is to recycle the cracked naphtha to the process unit to improve LPG and propylene yields.
The installation of propylene separation units can present a significant capital investment to refiners. However, these investments can be a strategic decision for downstream operators in the midterm to ensure higher added value from crude oil processing.
The petrochemical FCC alternative. In markets with high petrochemicals demand, the petrochemical FCCU can be an attractive alternative to refiners aiming to ensure higher added value to bottom-of-the-barrel streams.
For petrochemical FCCUs, the reaction temperature reaches 600°C (1,112°F) and a higher catalyst circulation rate increases gas production, which requires a scaling up of the gas separation section. The higher thermal demand leads to the catalyst regenerator operating in total combustion mode, making it necessary to install a catalyst cooling system. The most severe operating conditions of petrochemical FCCUs can increase the light olefins yield (ethylene + propylene + C4s) from 14% to 40%.
The installation of petrochemical catalytic cracking units requires a deep economic study, especially due to the high capital investment and higher operational costs. However, some industry forecasts show the demand for petrochemical intermediates increasing 4%/yr to 2025. In this scenario, the additional capital investment is attractive, as it can enable refiners to increase market share and put themselves in a more favorable competitive position through the maximization of petrochemical intermediates.
In refineries with conventional FCCUs, the addition of ZSM-5 additives can increase olefin yields by 9% in some cases. Although this also increases operational costs, it can be an attractive option due to future demand for petrochemical intermediates.
Steam cracking units. The steam cracking process serves a fundamental role in the petrochemical industry. Today, most light olefins and propylene are produced through steam cracking. Steam cracking consists of a thermal cracking process that uses gas or naphtha to produce olefins.
The naphtha steam cracking process is composed of straight-run naphtha from crude oil distillation units. Generally, to meet the requirements of petrochemical naphtha, the stream must present high paraffin content (> 66%).
The cracking reactions occur in the furnace tubes—the primary concern and limitation to the operating lifecycle of steam cracking units is coke formation in furnace tubes. The reactions are carried out under high temperatures [500°C–700°C (932°F–1,292°F)] depending on the characteristics of the feed. For heavier feeds like gasoil, a lower temperature is applied to minimize coke formation. The focus of a naphtha steam cracking unit is to produce ethylene; however, propylene yield in a typical naphtha steam cracking unit can reach 15%.
According to industry forecasts, propylene demand is expected to increase from 130 MMt in 2020 to approximately 190 MMt in 2030. Since light feed to refineries and steam cracking units tend to favor ethylene production, propylene demand tends to be supplied by on-purpose propylene production routes, such as propane dehydrogenation (PDH), methanol-to-olefins (MTO) reactions and olefins metathesis.
PDH. One route to propylene production is to produce light olefins through the dehydrogenation of light paraffins (C2–C5). Depending on the refiner’s regional market, capital investments in process units capable of producing light olefins through paraffin dehydrogenation can be an attractive strategy.
Light paraffins are normally commercialized as LPG or gasoline and are not as economically valued as light olefins. The dehydrogenation process involves removing H2 from the paraffinic molecule (Eq. 1):
R2CH-CHR2 ↔ R2C=CR2 + H2 (1)
The dehydrogenation reactions have strong endothermic characteristics, and the reaction conditions include high temperatures [nearly 600°C (1,112°F)] and mild operating pressures (near 5 bar). The catalysts typically applied in dehydrogenation reactions are platinum carried on alumina (other active metals can be applied).
FIG. 11 shows a schematic process flow diagram for a typical dehydrogenation process unit. The processes that can produce light paraffin-rich streams are physical separation processes using LPG from atmospheric distillation and other units to separate gases from crude oil.
The feed stream is mixed with the recycle stream before it enters the reactor. The products are separated in fractionation columns, and the H2 produced is sent to purification units [normally pressure swing adsorption (PSA) units]. From there and depending on the refinery’s design, it is sent to hydrotreating and hydrocracking units. After treatment, light compounds are directed to the refinery’s or the petrochemical complex’s fuel gas pool, while the olefinic stream is sent to the petrochemical-intermediates consumer market.
During the dehydrogenation process, there is a strong tendency for coke to deposit on the catalysts’ surface, leading to the need for regeneration of the catalytic bed through controlled combustion of the produced coke. Some process arrangements present two reactors in parallel to optimize the processing unit’s operational availability. While one reactor is in production, the other is in the regeneration step.
Due to high energy consumption, there is ongoing research to develop more active and selective catalysts that can reduce the need for energetic contribution to the dehydrogenation process. One of the main variations of the dehydrogenation process is called oxidative dehydrogenation (Eq. 2):
R2CH-CHR2 + O2 ↔ R2C=CR2 + H2O (2)
This reaction is strongly exothermic, which is one of the main advantages it has vs. the traditional dehydrogenation process.
Olefins metathesis. The olefins metathesis process involves the combination of ethylene and butene to produce propylene (Eq. 3):
H2C = CH2 + H3C – HC = CH – CH3 → 2H2C=HC – CH3 (3)
The economic viability of olefins metathesis units relies on the price gap between propylene and ethylene, as well as ethane availability in the market.
MTO. Another alternative route to produce liquid hydrocarbons from syngas is the non-catalytic conversion of natural gas to methanol followed by the polymerization to produce alkenes. Methanol is produced from natural gas by the following chemical reactions:
In the sequence, methanol is dehydrated to produce dimethyl ether (DME), which is dehydrated to produce hydrocarbons, as shown in the following sequence:
Methanol conversions to olefins into hydrocarbons are called MTO or methanol-to-gasoline (MTG) technologies. MTO technologies present some advantages in relation to Fischer-Tropsch (F-T) processes, such as a higher selectivity in hydrocarbon production, the products obtained require fewer processing steps to achieve commercial specifications, installation costs tend to be lower for MTO process plants vs. F-T units, and F-T units tend to only be economically viable at large scale.
Takeaways. There are competitive advantages in producing propylene through refinery purification (propylene separation from FCC LPG and olefins recovery from offgas). This work reinforces the advantages that integrated refiners gain when they can maximize propylene production in their refining assets. Other routes through steam cracking and PDH are cost competitive but have a higher dependence on feedstock costs.
Globally, there is a potential competitive imbalance in the short term due to the growing demand for petrochemicals. According to industry data, total capital investment in crude-to-chemical refineries was $300 B, with 64% of this investment being made by Asian players. FIG. 12 provides a comparison between the relation of crude oil distillation capacity and the integrated refinery capacity for each region.
FIG. 12 shows that Asian players have a superior integration capacity of their refining assets vs. other regions. This can be translated into a significant competitive advantage to Asian players, and the potential of a competitive imbalance in the downstream HPI.
Maximizing propylene in refining assets can offer attractive opportunities to refiners, especially those operating in regions with an oversupplied transportation fuels market. Despite the advantages of the propylene market, competitiveness is strongly dependent on operating costs. The primary factor in propylene production costs is the cost of raw materials; however, another fundamental factor is the technology utilized to produce propylene. Refiners that can minimize operating costs will gain an even stronger competitive edge in the market. This is especially true with closer integration between refining and petrochemical assets. HP
LITERATURE CITED
MARCIO WAGNER DA SILVA is a Process Engineer and Stockpiling Manager at Petrobras. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking bottom-barrel units. Dr. Silva earned a Bch degree in chemical engineering from the University of Maringa, Brazil, and a PhD in chemical engineering from the University of Campinas (UNICAMP), Brazil. In addition, he earned an MBA degree in project management from the Federal University of Rio de Janeiro, and in digital transformation at PUC/RS, and is certified in business from the Getúlio Vargas Foundation.